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INTRODUCTION
The Nigeria Tax Act, 2025 (“NTA”) introduces a recalibrated incentive framework aimed at attracting investment and driving growth across Nigeria’s petroleum sector. While the Petroleum Industry Act, 2021 (“PIA”) introduced a range of fiscal incentives, the NTA refines and expands these mechanisms, with a clearer emphasis on gas development, infrastructure investment, and other priority segments of the industry. By deploying a combination of tax credits, reduced royalty rates, VAT reliefs, and investment-linked incentives, the NTA seeks to improve project economics and enhance the competitiveness of Nigeria’s oil and gas sector.
This article examines the key fiscal incentives available under the NTA, highlighting their structure, scope, and potential impact on investment decisions within Nigeria’s petroleum industry.
Key Incentives for Oil and Gas Companies under the Nigeria Tax Act
1. Gas Production Tax Credit
The PIA did not provide for a Gas Production Tax Credit (“PTC”) as primary legislation. A PTC for non-associated gas was first introduced by the Oil and Gas Companies (Tax Incentives, Exemptions, Remissions, etc.) Order, 2024,1 a subsidiary instrument that did not form part of the PIA’s fiscal framework.
The NTA formally incorporates the PTC as a primary legislation incentive.2 It applies to the sale of non-associated gas from Greenfield Non-Associated Gas developments in onshore and shallow water terrains that achieve first commercial gas production between the commencement of the NTA and 1st January 2029. The PTC directly reduces tax liability, rather than merely reducing taxable income, for a period of ten years from first gas production.3 Upon expiry of the ten-year period, the PTC converts to a gas production allowance at the same rates, transitioning from a tax credit to an income deduction.4 This makes the PTC among the most valuable incentives available to gas developers, as a direct credit against tax payable delivers greater fiscal relief than an equivalent deduction from taxable income.
2. Production Allowance
Under the PIA, production allowances for crude oil applied as deductions in computing chargeable profits for HCT purposes.5 Operators who converted their Oil Mining Leases to Petroleum Mining Leases received tiered allowances based on terrain and cumulative production, while those who did not convert received lower allowances.
The NTA amends the PIA by deleting the relevant provision while substantially retaining this framework.6 Converted Petroleum Mining Lease operators receive the lower of US$2.50 per barrel or 20% of the fiscal oil price. Onshore Petroleum Mining Lease operators granted under the PIA receive the lower of US$8.00 per barrel or 20% of the fiscal oil price for their first 50 million barrels of cumulative production, reducing to the lower of US$4.00 per barrel or 20% thereafter. Shallow water operators receive the lower of US$8.00 per barrel or 20% for their first 100 million barrels, reducing to the lower of US$4.00 per barrel or 20% thereafter.
3. Gas Pipeline Investment Tax-Free Period
The NTA grants investors in gas pipelines a five-year tax-free period commencing after the expiration of their economic development incentive certificate.7 The NTA clarifies that this tax free period does not exempt the underlying commodity: natural gas transferred between streams, and natural gas liquids and LPG derived from gas, remain subject to applicable taxes.
The incentive operates at the infrastructure investment level only, supporting the commercial viability of pipeline projects that are critical to the development of Nigeria’s gas sector.
4. Economic Development Tax Credit
Prior to the NTA, companies in designated pioneer industries benefitted from income tax holidays under the Pioneer Status Incentive framework administered by the Nigerian Investment Promotion Commission. Upstream petroleum companies could access this framework in relation to eligible activities, but it was not petroleum-specific and was administered separately from the petroleum fiscal regime.
The NTA replaces this with the Economic Development Tax Credit (“EDT Credit”), a performance-linked incentive applicable to priority sectors listed in the Tenth Schedule, which includes crude oil and gas refining, electricity and gas supply, gas production and utilisation, and transportation and distribution of gas.8 Under the NTA, eligible companies may claim a 5% annual tax credit on qualifying capital expenditure for five years,9 evidenced by an economic development incentive certificate. The credit is applied directly against tax payable, and unutilised credit may be carried forward for a further five years. The direct-credit structure makes the EDT Credit more valuable than the predecessor income tax holiday in situations where the company is already in a taxable position.
5. Reduced Royalty Rate for Domestic Gas Utilisation
Under the PIA, the royalty rate for natural gas and natural gas liquids was set at 5% of the chargeable volume, with a reduced rate of 2.5% available for natural gas produced and utilised in-country.10 The NTA amends the PIA by deleting that provision and restating the same royalty framework, including the 2.5% rate for gas utilised domestically.11 This incentive continues to provide a material fiscal advantage for operators who direct their gas production towards domestic supply, in line with Nigeria’s broader gas monetisation policy.
6. Reduced Royalty Rates for Small-Scale Production
The PIA introduced reduced royalty rates for marginal fields and smaller production volumes to encourage indigenous operators and stimulate production from fields that would otherwise be commercially unviable at standard royalty rates.12 While the standard royalty rates are 15% for onshore, 12.5% for shallow water, and 7.5% for deep offshore production, the PIA provided concessions for lower production volumes: for onshore and shallow water fields producing 10,000 barrels per day or less, a tranched royalty applied, with the first 5,000 barrels per day subject to 5% and the next 5,000 barrels per day subject to 7.5%; and for deep offshore fields producing 50,000 barrels per day or less, a reduced rate of 5% applied.
The NTA retains these reduced royalty structures and restates the concessions provided under the PIA.13 These reductions lower early cash outflows during capital-intensive development phases and are particularly beneficial for indigenous companies operating smaller fields.
7. Reduced Royalty Rates for Frontier Basins
Under the PIA, frontier acreages were exempted from HCT until reclassified as general onshore areas. In addition, the PIA provided a reduced royalty rate of 7.5% for crude oil produced from frontier basins, compared to the standard onshore rate of 15%, and excluded frontier production from the application of price-based royalty.14
The NTA preserves the HCT exemption for frontier acreages and retains these incentives under its royalty framework, including the 7.5% rate for frontier basin production and the exclusion from additional price-based royalty.15 These measures continue to support exploration activity in underexplored basins by reducing the fiscal burden during what are typically extended and costly exploration periods.
8. Value Added Tax Exemptions
The NTA consolidates and expands VAT relief for the sector. It exempts oil and gas exports from VAT and lists crude petroleum oil and feed gas for all processed gas feeds as exempt supplies.16 As noted above, the NTA also suspends VAT on petroleum products, CNG, LNG, LPG, and other gaseous hydrocarbons, pending a commencement order by the Minister of Finance. Together, these provisions significantly reduce the VAT burden on oil and gas operators across the supply chain and support the competitiveness of Nigerian petroleum in export markets.
CONCLUSION
The incentive framework under the NTA reflects a more targeted and performance-driven approach to fiscal policy in Nigeria’s petroleum sector. Rather than broad-based concessions, the regime prioritises incentives that are closely aligned with national objectives, particularly in relation to gas development, infrastructure expansion, and domestic utilisation.
For operators and investors, the significance of these incentives lies in their strategic application. Maximising their value will require careful planning, a clear understanding of qualifying conditions, and a proactive approach to integrating them into project and financing structures. In an increasingly competitive energy landscape, those who effectively leverage these incentives will be better positioned to unlock value and sustain long-term participation in Nigeria’s petroleum industry.
Footnotes
1. Section 1(5), Oil and Gas Companies (Tax Incentives, Exemption, Remission, Etc.) Order, 2024.
2. Section 85(1), Nigeria Tax Act, 2025.
3. Section 85(1)(d), Nigeria Tax Act, 2025.
4. Section 85(1)(e), Nigeria Tax Act, 2025.
5. Paragraph 1, Sixth Schedule, Petroleum Industry Act, 2021.
6. Section 71(1) and Paragraph 1 of the Sixth Schedule, Nigeria Tax Act, 2025.
7. Section 80(1); Section 166(1), Nigeria Tax Act, 2025.
8. Section 166, Nigeria Tax Act, 2025.
9. Section 178, Nigeria Tax Act, 2025.
10. Paragraph 10(6) of Part 3, Seventh Schedule, Petroleum Industry Act, 2021.
11. Paragraph 6(2)(f) of Part 3, Seventh Schedule, Nigeria Tax Act, 2025.
12. Paragraph 10, Part 3, Seventh Schedule, Petroleum Industry Act, 2021.
13. Paragraph 6 of Part 3, Seventh Schedule, Nigeria Tax Act, 2025.
14. Section 260(3), Petroleum Industry Act, 2021; Section 65(4), Nigeria Tax Act, 2025.
15. Paragraph 6(3)(b), Seventh Schedule, Nigeria Tax Act, 2025.
16. Section 143; Section 186(1), Nigeria Tax Act, 2025.
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.
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